CN102374124B - Apparatus and method for operation of a wind turbine - Google Patents

Abstract

The invention relates to a device and a method for the operation of a wind turbine. A method for operating a wind turbine (10) is provided. A wind turbine (10) includes a rotor (18) including at least one rotor blade (22) and a pitch drive system (68) coupled to the at least one rotor blade (22). A pitch drive system (68) is adapted to pitch the rotor blades (22). The method comprises: determining an actual value of a first variable indicative of an overspeed condition of the wind turbine (10); determining an actual value of a second variable of the wind turbine (10) related to a rate of change of the first variable with respect to time; and Occurrence of an overspeed condition of the wind turbine (10) is estimated based on at least the determined actual values of the first variable and the second variable. A pitch drive system (68) pitches the at least one rotor blade (22) based on the estimated result to aerodynamically brake the rotor (18).

Description

Device and method for operation of a wind turbine

technical field

The subject matter described herein relates generally to methods and systems for operating a wind turbine, and more particularly, to methods and systems for operating a control assembly for a wind turbine.

Background technique

At least some known wind turbines include a tower and a nacelle mounted on the tower. A rotor is rotatably mounted to the nacelle and is coupled to the generator by a rotor shaft. In a typical wind turbine, a plurality of blades extend from the rotor. The blades are oriented in such a way that wind passing over the blades turns the rotor and rotates the rotor shaft, driving a generator to generate electricity.

At least some known wind turbines are operated by a control system. Furthermore, at least some known control systems for wind turbines achieve their pitch control through rotation of the rotor blades about a pitch axis. That is, these control systems are designed to adjust the rotor speed of the wind turbine by setting the angle of the blades relative to the air flow (ie, pitching the blades). Pitching the blades to reduce rotor speed generally results in increased loads acting on some of the components of the wind turbine, such as the blades, the rotor, or the wind turbine tower.

In general, an increase in the speed of the wind impinging on the rotor blades results in an increase in the rotor speed. Under certain conditions, such as high winds in the area of the wind turbine, the rotor speed may eventually exceed a threshold corresponding to the maximum allowed speed of the wind turbine (ie overspeed).

At least some known control systems that implement pitch control are designed to monitor the rotor speed by determining the actual value of the rotor speed, and to increase the pitch angle of the blades whenever the actual value of the rotor speed exceeds the maximum allowable speed of the wind turbine. to aerodynamically slow down the rotor (ie, brake the rotor). In this case, reducing the rotor speed by pitching the blades may lead to a particularly significant increase in the loads acting on components of the wind turbine. Generally, such significant load increases can adversely affect the operating life of the turbine. In at least some known pitch control systems, a pitch controller drives the rotor speed back below the maximum allowable speed of the wind turbine. At least some of these pitch control systems are designed to reduce the pitch angle as soon as the rotor speed is below the maximum allowable speed of the wind turbine, in order to maintain a high rotor speed, but keep the rotor speed within the safety boundaries of the wind turbine (i.e. , below the maximum allowable speed of the wind turbine).

In such overspeed events, regulated by known control systems, the increase and subsequent decrease of the pitch angle generally results in alternating forces acting on the tower. In some cases, these alternating forces can excite resonant modes of the tower and cause the tower to resonate. Such resonance of the tower may require shutdown of the wind turbine when the vibration exceeds the maximum allowable limit. A shutdown event generally means a loss of the wind turbine's capacity to generate power.

Accordingly, it would be desirable to provide methods and/or apparatus that enable pitch control that avoids high loads on wind turbine components and/or reduces wind turbine stress due to wind turbine Risk of downtime due to overspeed conditions.

Contents of the invention

Embodiments described herein include a control assembly that estimates the occurrence of an overspeed condition of the wind (turbine) from actual values of a plurality of variables of the wind turbine, and pitches at least one rotor blade based on the estimated result. Embodiments described herein enable smooth pitching of rotor blades by estimating the occurrence of an overspeed condition. Thus, this pitching typically results in smooth braking of the rotor. Thus, transient loads on wind turbine components are typically reduced and the operating life of the wind turbine is typically extended. Furthermore, such smooth pitching typically reduces wind turbine resonance and the risk of wind turbine downtime. Specifically, according to at least one embodiment, the rotor blades are pitched in such a way that a first variable of the wind turbine, eg rotor speed, does not exceed a threshold value indicative of an overspeed condition of the wind turbine.

In one aspect, a method for operating a wind turbine is provided. A wind turbine includes a rotor including at least one rotor blade and a pitch drive system coupled to the at least one rotor blade. The pitch drive system is adapted to pitch the at least one rotor blade. The method comprises: determining an actual value of a first variable indicative of an overspeed condition of the wind turbine; determining an actual value of a second variable of the wind turbine related to a rate of change of the first variable with respect to time; and, based at least on the first variable and the determined actual value of the second variable to estimate the occurrence of an overspeed condition of the wind turbine. A pitch drive system pitches the at least one rotor blade based on the estimated result in order to aerodynamically brake the rotor. In certain embodiments of the present disclosure, the first variable indicates an overspeed condition of the wind turbine when it exceeds a threshold value.

In another aspect, a control assembly for a wind turbine is provided. A wind turbine includes a rotor including at least one rotor blade. The control assembly includes a pitch drive system coupled to the at least one rotor blade, the pitch drive system being adapted to pitch the at least one rotor blade. The wind turbine further includes a control system communicatively coupled (ie, communicatively coupled) to the pitch drive system. The control system is configured to: determine an actual value of a first variable indicative of an overspeed condition of the wind turbine; determine an actual value of a second variable of the wind turbine related to a rate of change of the first variable with respect to time; and, at least based on the first The determined actual values of the variable and the second variable are used to estimate the occurrence of an overspeed condition of the wind turbine. The control system is configured to control the pitch drive system based on the estimated result in such a way that the pitch drive system is controlled to pitch at least one rotor blade in order to aerodynamically brake the rotor.

In yet another aspect, a method for operating a wind turbine is provided. A wind turbine includes a rotor including at least one rotor blade and a pitch drive system coupled to the at least one rotor blade, the pitch drive system being adapted to pitch the at least one rotor blade. The method includes: determining an actual value of a reference speed proportional to the rotational speed of the rotor; determining an actual value of a rate of change of the reference speed with respect to time; and, evaluating the determined actual value of the reference speed and the rate of change of the reference speed with respect to time rate of change to identify wind turbine overspeed conditions. When an overspeed condition of the wind turbine is identified in the evaluation, the pitch drive system rotates the at least one rotor blade.

Further aspects, advantages and features of the invention are apparent from the dependent claims, the description and the figures.

Description of drawings

A complete and enabling disclosure, including the best mode thereof, is set forth more particularly to those of ordinary skill in the art in the remainder of the specification, including reference to the accompanying drawings, in which:

Figure 1 is a perspective view of an exemplary wind turbine;

Figure 2 is an enlarged cross-sectional view of a portion of the wind turbine shown in Figure 1;

3 is a block diagram of an exemplary control assembly of the wind turbine in FIG. 1;

4 is a block diagram of an exemplary control system of a control assembly of the wind turbine in FIG. 1;

FIG. 5 is a flowchart illustrating an exemplary method for operating the wind turbine in FIG. 1;

FIG. 6 is a flowchart illustrating another exemplary method for operating the wind turbine in FIG. 1; and,

Fig. 7 is a schematic graphical representation of the response of the wind turbine in Fig. 1 to an identified overspeed condition as compared to the response of at least some known wind turbines.

Parts list:

10 wind turbines

12 towers

14 support system

16 cabins

18 rotors

20 rotatable hub

22 rotor blades

24 leaf root part

26 load transfer area

28 directions

30 axis of rotation

32 pitch adjustment system

34 pitch axis

36 control system

38 yaw axis

40 processors

42 Generators

44 rotor shaft

46 gear box

48 high speed shaft

50 connectors

52 supports

54 supports

56 Yaw drive mechanism

58 weather pole

60 front support bearing

62 rear support bearing

64 drive train

66 pitch components

68 pitch drive system

70 speed sensor

72 pitch bearing

74 pitch drive motor

76 pitch transmission gearbox

78 pitch drive pinion

82 cables

84 generators

86 cavities

88 inner surface

90 outer surface

92 control components

94 sensor system

116 longitudinal axis

500 exemplary methods

502 determination steps

504 determination steps

506 evaluation steps

508 identification steps

510 spin steps

600 exemplary methods

602 Confirmation step

604 determination step

606 evaluation steps

608 identification steps

610 rotation steps

Line 702

703 Predetermined rotor speed

704 line

Detailed ways

Reference will now be made in detail to various embodiments, one or more examples of which are shown in the various figures. Each example is provided by way of illustration and not intended as a limitation. For example, features illustrated or described as part of one embodiment can be used on or in conjunction with other embodiments to yield still other embodiments. It is intended that the present disclosure includes such modifications and variations.

According to embodiments described herein, a wind turbine operates a pitch drive system for rotating a rotor blade based on a result of an estimation of the occurrence of an overspeed condition of the wind turbine. The estimate is based on determined actual values of a plurality of values of the wind turbine. At least one of these variables, referred to as the first variable, is indicative of an overspeed condition of the wind turbine. For example, the first variable may be the rotor speed, which indicates an overspeed of the wind turbine when it exceeds the maximum allowed speed of the wind turbine (ie overspeed). Alternatively, the first variable may be the power output of the wind turbine, the curvature of one or more rotor blades, the wind speed in the environment of the wind turbine, or any other variable indicative of an overspeed condition of the wind turbine when it exceeds a threshold. Typically, the first variable of a wind turbine is a variable that is monotonically related to the rotor speed. At least one other of these variables, referred to as a second variable, is related to the rate of change of the first variable with respect to time. In the example above, the second variable may be rotor acceleration. Typically, the second variable is monotonically related to the rotational acceleration of the rotor. According to at least some embodiments, the estimate may be based on additional variables of the wind turbine. In the above example, the second, third or even higher order derivatives of the first variable (eg rotor speed) may be used for this estimation.

According to some embodiments, the pitch drive system rotates the rotor blades to aerodynamically brake the rotor when it is estimated that an overspeed condition will occur within a predetermined time. For example, the estimating may include calculating a value for the rotor speed (ie, the future rotor speed) over a predetermined period of time based on the determined actual values of the first variable and the second variable, and comparing the identified future rotor speed with A predetermined rotor speed value typically corresponding to the maximum allowed speed of the wind turbine. In this example, if the identified future rotor speed exceeds a predetermined rotor speed, it is estimated that an overspeed condition will occur within that time period, and the pitch drive system then pitches the rotor blade or blades , in order to aerodynamically brake the rotor.

Embodiments described herein provide a wind turbine that enables a pitch assembly to smoothly rotate a rotor blade about a pitch axis (ie, smoothly pitch the rotor blade). In particular, embodiments described herein facilitate performing pitching before the wind turbine is in an overspeed condition. Furthermore, according to some embodiments, the pitching is performed in such a way that the estimated overspeed condition does not occur.

Accordingly, embodiments described herein typically facilitate reducing aerodynamic loads in components of a wind turbine, which typically increases the operational lifetime of the wind turbine. Furthermore, wind turbines according to embodiments described herein typically facilitate avoiding overspeed-induced shutdowns. Accordingly, embodiments described herein typically facilitate increasing the power generating capacity of a wind turbine. As used herein, the term "overspeed condition" refers to a condition of a wind turbine in which the rotor of the wind turbine rotates at a speed at which potential damage to the rotor, including to the rotor blades of the wind turbine, can occur or other components such as generators coupled to the rotor.

As used herein, the term variable of a wind turbine is intended to mean a quantity related to a wind turbine that varies over time. Some examples of variables of a wind turbine are rotor speed (i.e. the rate of rotation of the rotor), rotor acceleration (e.g. rotor rotational or axial acceleration), the curvature of the rotor blades or the power output of the wind turbine, e.g. The power output of the generator.

As used herein, the term actual value of a variable of the wind turbine is intended to mean the value of the variable actually employed by the wind turbine. For example, the actual value of the rotor speed may be determined from direct measurements of the rotor speed obtained by sensors. Alternatively, the actual rotor speed may be determined by estimating a variable of the wind turbine based on a measured value of another variable such as, but not limited to, the rotational speed of the rotor shaft or a high speed shaft coupled to the rotor shaft through a gear system. value. For example, the actual value of the rotor acceleration may correspond to a direct measure of the acceleration obtained by a sensor coupled to the rotor. Alternatively, the actual value of the rotor acceleration may correspond to a rate of change of the actual value of the rotor speed with respect to time, which rate may be deduced from the time series of rotor speed values. Such variables of the wind turbine may be determined by any suitable method that enables the wind turbine to operate as described herein.

As used herein, the term "vane" is intended to mean any device that provides a reaction force when in motion relative to the surrounding fluid. As used herein, the term "wind turbine" is intended to mean any device that generates rotational energy from wind energy, and more specifically converts kinetic energy of wind into mechanical energy. As used herein, the term "wind generator" is intended to mean any wind turbine that uses rotational energy generated from wind energy to generate electrical power, and more specifically converts mechanical energy converted from kinetic energy of the wind into electrical power.

In the following description of the drawings, the same reference numerals refer to the same components. In general, only differences with respect to individual embodiments are described.

FIG. 1 is a perspective view of an exemplary wind turbine 10 . In the exemplary embodiment, wind turbine 10 is a horizontal axis wind turbine. Alternatively, wind turbine 10 may be a vertical axis wind turbine. In the exemplary embodiment, wind turbine 10 includes a tower 12 extending from a support system 14 , a nacelle 16 mounted on tower 12 , and a rotor 18 coupled to nacelle 16 . Rotor 18 includes a rotatable hub 20 and at least one rotor blade 22 coupled to and extending outwardly from hub 20 . In the exemplary embodiment, rotor 18 has three rotor blades 22 . In alternative embodiments, rotor 18 includes more or less than three rotor blades 22 , such as one or four blades. In the exemplary embodiment, tower 12 is fabricated from tubular steel to define a cavity (not shown in FIG. 1 ) between support system 14 and nacelle 16 . In an alternate embodiment, tower 12 is any suitable type of tower having any suitable height.

Rotor blades 22 are spaced about hub 20 to facilitate rotating rotor 18 to enable the conversion of kinetic energy from the wind into usable mechanical energy, and subsequently electrical energy. Rotor blade 22 is mated to hub 20 by coupling blade root portion 24 to hub 20 at a plurality of load transfer regions 26 . The load transfer area 26 has a hub load transfer area and a blade load transfer area (both not shown in FIG. 1 ). Loads induced on rotor blade 22 are transferred to hub 20 via load transfer region 26 .

In one embodiment, rotor blade 22 has a length ranging from about 15 meters (m) to about 91 meters. Alternatively, rotor blades 22 may have any suitable length that enables wind turbine 10 to function as described herein. For example, other non-limiting examples of blade lengths include lengths of 10 m or less, 20 m, 37 m, or greater than 91 m. As wind strikes rotor blades 22 from a direction 28 , rotor 18 rotates about an axis of rotation 30 . As rotor blades 22 rotate and experience centrifugal forces, rotor blades 22 are also subjected to various forces and moments. Thus, rotor blades 22 may deflect and/or rotate from a neutral or non-deflected position to a deflected position.

Furthermore, the pitch angle or blade pitch of the rotor blades 22 (ie, the angle determining the projection of the rotor blades 22 with respect to the direction 28 of the wind) can be varied by the pitch adjustment system 32 to adjust the pitch of at least one rotor blade 22 relative to The rotational position of the wind vector controls the load and power produced by wind turbine 10 . In an alternative embodiment, the pitch angle of only a portion of rotor blades 22 is varied by pitch adjustment system 32 . The pitch axis 34 of the rotor blade 22 is shown in FIG. 1 . During operation of wind turbine 10, pitch adjustment system 32 may vary the blade pitch of rotor blades 22 such that rotor blades 22 move to a feathered position in such a way that the projection of at least one rotor blade 22 with respect to the wind vector Providing a minimum surface area of rotor blades 22 that will be oriented towards the wind vector facilitates reducing the rotational speed of rotor 18 and/or facilitates stalling of rotor 18 .

In the exemplary embodiment, the blade pitch of each rotor blade 22 is individually controlled by control system 36 . Alternatively, the blade pitch of all rotor blades 22 may be controlled by control system 36 simultaneously. Additionally, in the exemplary embodiment, the yaw direction of nacelle 16 may be controlled about yaw axis 38 to position rotor blades 22 relative to direction 28 as direction 28 changes.

In the exemplary embodiment, control system 36 is shown centralized within nacelle 16 . Alternatively, control system 36 may be a distributed system throughout wind turbine 10 , on support system 14 , within the wind farm, and/or at a remote control center. Control system 36 includes a processor 40 configured to perform the methods and/or steps described herein. Additionally, many of the other components described herein include processors. As used herein, the term "processor" is not limited to integrated circuits known in the art as computers, but broadly refers to controllers, microcontrollers, microcomputers, programmable logic controllers (PLCs), application-specific integrated circuits, and other programmable circuits, and these terms are used interchangeably herein. It should be understood that the processor and/or control system may also include memory, input channels, and/or output channels.

In embodiments described herein, memory may include, without limitation, computer-readable media such as random access memory (RAM), as well as computer-readable non-volatile media such as flash memory. Alternatively, a magnetic disk, compact disk read only memory (CD-ROM), magneto-optical disk (MOD) and/or digital versatile disk (DVD) may also be used. Also, in the embodiments described herein, input channels include, without limitation, sensors and/or computer peripherals associated with an operator interface, such as a mouse and keyboard. Additionally, in the exemplary embodiment, an output channel may include, without limitation, a control device, an operator interface monitor, and/or a display.

The processors described herein process information transmitted from a number of electrical and electronic devices, which may include, but are not limited to, sensors, actuators, compressors, control systems, and/or monitoring devices. Such processors may be physically located in, for example, control systems, sensors, monitoring devices, desktop computers, laptop computers, programmable logic controller (PLC) cabinets, and/or distributed control system (DCS) cabinets. RAM and storage devices store and transfer information and instructions to be executed by the processor(s). RAM and storage devices can also be used to store and provide temporary variables, static (ie, non-changing) information and instructions or other intermediate information to the processor(s) during execution of instructions. The executed instructions may include, but are not limited to, wind turbine control system control commands. The execution of sequences of instructions is not limited to any specific combination of hardware circuitry and software instructions.

FIG. 2 is an enlarged cross-sectional view of a portion of wind turbine 10 . In the exemplary embodiment, wind turbine 10 includes nacelle 16 and hub 20 rotatably coupled to nacelle 16 . More specifically, hub 20 is rotatably coupled to generator 42 positioned within nacelle 16 via rotor shaft 44 (sometimes referred to as either a main shaft or low speed shaft), gearbox 46 , high speed shaft 48 and coupling 50 . In the exemplary embodiment, rotor shaft 44 is disposed coaxially with longitudinal axis 116 . Rotation of rotor shaft 44 rotatably drives gearbox 46 , which in turn drives high speed shaft 48 . High speed shaft 48 rotatably drives generator 42 with coupling 50 , and rotation of high speed shaft 48 facilitates generation of electrical power by generator 42 . Gearbox 46 and generator 42 are supported by supports 52 and 54 . In the exemplary embodiment, gearbox 46 drives high speed shaft 48 using a dual path geometry. Alternatively, rotor shaft 44 is coupled directly to generator 42 with coupling 50 .

In the exemplary embodiment, nacelle 16 also includes yaw drive mechanism 56 that may be used to rotate nacelle 16 and hub 20 on yaw axis 38 (shown in FIG. 1 ) to control the rotor blades. The projection of 22 relative to the direction of the wind 28 . Nacelle 16 also includes at least one weather mast 58 that includes a wind vane and anemometer (neither shown in FIG. 2 ). Mast 58 provides information to control system 36 which may include wind direction and/or wind speed. In the exemplary embodiment, nacelle 16 also includes main front support bearings 60 and main rear support bearings 62 .

Front support bearing 60 and rear support bearing 62 facilitate radial support and alignment of rotor shaft 44 . Front support bearing 60 is coupled to rotor shaft 44 in the vicinity of hub 20 . Aft support bearing 62 is positioned on rotor shaft 44 in the vicinity of gearbox 46 and/or generator 42 . Alternatively, nacelle 16 includes any number of support bearings that enable wind turbine 10 to function as disclosed herein. rotor shaft 44, generator 42, gearbox 46, high speed shaft 48, coupling 50 and any associated fasteners, supports and/or fixtures (including but not limited to supports 52 and/or supports 54, Front support bearing 60, rear support bearing 62) are sometimes referred to as drive train 64.

In the exemplary embodiment, hub 20 includes pitch assembly 66 . Pitch assembly 66 includes one or more pitch drive systems 68 . In the exemplary embodiment, nacelle 16 includes a sensor system that may include at least one sensor, such as speed sensor 70 , for sensing at least one variable of wind turbine 10 , such as the speed or acceleration of at least one rotor blade 22 . . Typically, the at least one sensor of the sensor system is communicatively coupled to the control system 36, as described in more detail below. Typically, each pitch drive system 68 is coupled to a respective rotor blade 22 (shown in FIG. 1 ) to adjust the blade pitch of the associated rotor blade 22 along the pitch axis 34 . Only one of the three pitch drive systems 68 is shown in FIG. 2 .

In the exemplary embodiment, pitch assembly 66 includes at least one pitch bearing 72 coupled to hub 20 and to a corresponding rotor blade 22 (shown in FIG. 1 ) for The respective rotor blade 22 is rotated about a pitch axis 34 . Pitch drive system 68 includes pitch drive motor 74 , pitch drive gearbox 76 and pitch drive pinion 78 . Pitch drive motor 74 is coupled to pitch transfer gearbox 76 in such a manner that pitch drive motor 74 exerts a mechanical force on pitch transfer gearbox 76 . Pitch transfer gearbox 76 is coupled to pitch transfer pinion 78 in such a manner that pitch transfer gearbox 76 rotates pitch transfer pinion 78 . Pitch bearing 72 is coupled to pitch drive pinion 78 in such a manner that rotation of pitch drive pinion 78 causes rotation of pitch bearing 72 . More specifically, in the exemplary embodiment, pitch drive pinion 78 is coupled to pitch bearing 72 such that rotation of pitch drive gearbox 76 causes pitch bearing 72 and rotor blades 22 to rotate about the pitch axis. 34 rotates to change the blade pitch of the blades 22.

In the exemplary embodiment, pitch drive system 68 is coupled to control system 36 to adjust the blade pitch of rotor blades 22 upon receiving one or more signals from control system 36 . Pitch drive motor 74 is any suitable motor driven by electrical power and/or a hydraulic system that enables pitch assembly 66 to function as described herein. Alternatively, pitch assembly 66 may include any suitable structure, configuration, arrangement, and/or components, such as, but not limited to, hydraulic cylinders, springs, and/or servo mechanisms. Additionally, pitch assembly 66 may be actuated by any suitable means, such as, but not limited to, hydraulic fluid and/or mechanical power, such as, but not limited to induced spring force and/or electromagnetic force. In certain embodiments, pitch drive motor 74 is driven by energy extracted from the rotational inertia of hub 20 and/or a stored energy source (not shown) that supplies energy to components of wind turbine 10 .

FIG. 3 is a block diagram of an exemplary control assembly 92 . In the exemplary embodiment, control assembly 92 includes pitch drive system 68 , control system 36 and sensor system 94 . Control assembly 92 may include any other suitable device that enables control assembly 92 to function as described herein. According to certain embodiments, pitch drive system 68 is coupled to at least one rotor blade 22 to rotate the rotor blade about pitch axis 34 . In the exemplary embodiment, pitch drive system 68 corresponds to the pitch drive system described above. Pitch drive system 68 is communicatively coupled to control system 36 such that pitch drive system 68 can adjust the blade pitch of rotor blades 22 upon receiving one or more signals from control system 36 .

According to certain embodiments, control system 36 is communicatively coupled to pitch drive system 68 and is configured to estimate the occurrence of an overspeed condition based on at least determined actual values of the first variable and the second variable of wind turbine 10 . In the exemplary embodiment, control system 36 determines the actual value via sensor system 94 .

According to some embodiments, the first variable is monotonically related to the rotational speed of the rotor 18 and/or the second variable is monotonically related to the rotational acceleration of the rotor 18 . As used herein, the term monotonic correlation indicates an increasing and decreasing relationship between two variables of a wind turbine implying their correlation. For example, as set forth above, wind turbine 10 may include a high speed shaft 48 coupled to rotor shaft 44 through gearbox 46 . In these embodiments, the rotational speed of the high speed shaft 48 is typically directly proportional to the rotor speed. Therefore, as used herein, the rotational speed of the high speed shaft 48 is considered to be monotonically related to the rotor speed. As another example, in the exemplary embodiment, wind turbine 10 includes generator 42 for generating an electrical power output. Electrical power output is typically proportional to the cube of the rotor speed. Therefore, as used herein, power output is considered to be monotonically related to rotor speed.

According to at least some embodiments, control system 36 determines the actual value of the first variable via sensor system 94 and determines the actual value of the second variable via the determined value of the first variable. For example, control system 36 may be configured to determine the actual value of the second variable by calculating the rate of change of the first variable with respect to time. Specifically, the control system 36 may determine the actual value of the rotor speed (ie, the first variable in this case) through the sensor system 94 and may determine the rotor rotation by calculating the rate of change of the value of the rotor speed with respect to time. The actual value of the acceleration (ie the second variable in this case).

According to certain embodiments, pitch drive system 68 is configured to rotate rotor blades 22 based on the results of the estimations performed by control system 36 . For example, rotor blades 22 are rotated when control system 36 identifies, based on the determined actual values, that wind turbine 10 is about to enter an overspeed condition. In the exemplary embodiment, control system 36 communicates with pitch drive system 68 to signal that an overspeed condition will occur. When pitch drive system 68 receives a signal that an overspeed condition is present, it rotates rotor blades 22 toward a feathered position to reduce rotor speed (ie, aerodynamically brake rotor 18 ).

According to certain embodiments, sensor system 94 includes one or more sensors for measuring actual values of one or more variables of wind turbine 10 . In particular, sensor system 94 is communicatively coupled to control system 36 , typically to provide control system 36 with measured values of variables. Based on the received measured values, control system 36 typically determines actual values for one or more variables of wind turbine 10 . According to at least some of the embodiments, sensor system 36 is configured to measure at least one of actual values of a first variable and/or a second variable of wind turbine 10 , such as rotor speed and rotor acceleration.

According to certain embodiments, the sensor system 94 is adapted to be coupled to a rotatable part of the wind turbine 10, which is connected to the rotor 18, to establish a first variable or a second variable of the wind turbine by measuring the rotational speed of the rotatable part. The actual value of the two variables. In the exemplary embodiment, sensor system 94 includes speed sensor 70 for sensing rotor speed. Specifically, in the exemplary embodiment, speed sensor 70 is coupled to rotor shaft 44 to measure its rotational speed. According to certain embodiments, speed sensor 70 includes a proximity sensor configured to register rotation of rotor shaft 44 such that speed sensor 70 measures a rotational speed of rotor shaft 44 . The rotational speed of the rotor shaft 44 corresponds to the rotor speed. In alternative embodiments, sensor system 94 may include a sensor adapted to measure another variable of wind turbine 10 , such as a speed sensor coupled to high speed shaft 48 to measure its rotational speed. In alternative embodiments, sensor system 94 may include sensors adapted to measure a number of variables of wind turbine 10 (e.g., a speed sensor coupled to high speed shaft 48 to measure the rotational speed of high speed shaft 48, and a speed sensor coupled to rotor 18 Any arrangement of accelerometers to measure rotor acceleration).

In general, sensor system 94 may include any suitable sensor that provides measurements of variables of wind turbine 10 suitable to assist in estimating the occurrence of an overspeed condition. For example, sensor system 94 may include sensors coupled to the generator portion of wind turbine 10 (e.g., the output of generator 42) to establish a first-order value by measuring the power output of the generator portion and/or its rate of change with respect to time. At least one of the actual value of a variable or the actual value of a second variable.

According to at least some of the embodiments, sensor system 94 may be configured to measure actual values of wind speed in an area proximate to wind turbine 10 . In the exemplary embodiment, pole 58 forms part of sensor system 94 and provides wind speed and direction data to control system 36 . In these embodiments, it is typical for the control system 36 to be configured to identify an overspeed condition based further on the determined actual value of the wind speed. Accordingly, control system 36 may identify an overspeed condition of wind turbine 10 by considering the actual value of the wind speed to estimate the occurrence of an overspeed condition of wind turbine 10 .

According to certain embodiments, the sensor system 94 is configured to measure an actual value of the curvature of the rotor blade 22 . In these embodiments, sensor system 94 may include any suitable sensor that enables determination of the curvature of rotor blade 22 , such as a strain gauge sensor or an optical strain sensor.

According to certain embodiments, sensor system 94 is configured to measure acceleration of rotor 18 in a direction perpendicular to the longitudinal axis of hub 20 (ie, acceleration related to gravity). In such embodiments, sensor system 94 typically includes one or more acceleration sensors (not shown) mounted at or near one of rotor blades 22 to facilitate sensing the longitudinal direction of rotor 18 perpendicular to hub 20 . A first acceleration in a first direction of the axis and a second acceleration vector of the rotor 18 in a direction perpendicular to both the first direction and the longitudinal axis of the hub 20 . In such an embodiment, the occurrence of an overspeed condition is estimated using the measured value or values of acceleration and at least one actual value of another variable of wind turbine 10 .

In the exemplary embodiment, control system 94 determines the actual value of the first variable for the wind turbine based on the measured rotational speed. In some embodiments, the actual value is determined directly from at least one measured value. In other embodiments, the actual value of the first variable is obtained from at least one measured value of another variable. For example, in some embodiments, the first variable corresponds to rotor speed, and control system 36 determines the rotor speed by obtaining the rotor speed from a measure of the rotational speed of high speed shaft 48 . In these embodiments, control system 36 typically takes into account gear ratios to obtain an actual value for rotor speed based on the measured rotational speed of high speed shaft 48 . In the exemplary embodiment, control system 36 determines the actual value of the second variable based on the rate of change of the measured value of rotor speed with respect to time. Alternatively, control system 36 determines the actual value of the second variable directly from the measure of rotor acceleration provided by sensor system 94 . As explained above, the control system 36 evaluates the determined actual values of the first variable and the second variable to estimate the occurrence of an overspeed condition of the wind turbine 10 .

FIG. 4 is a block diagram of an exemplary control system 36 forming part of the control assembly of wind turbine 10 of FIG. 1 . In the exemplary embodiment, control system 36 includes controller 102 , memory 104 and communication module 106 . Control system 36 may include any suitable device that enables control system 36 to function as described herein. In the exemplary embodiment, communication module 106 includes sensor interface 108 that facilitates enabling controller 102 to communicate with sensor system 94 . In one embodiment, sensor interface 108 includes an analog/digital converter that converts an analog voltage signal generated by the sensor into a multi-bit digital signal usable by controller 102 . In alternative embodiments, the communication module 106 may include any device that facilitates transmission of signals to any device located on the wind turbine (e.g., at the rotor shaft 44, or within or external to and/or remote from the rotor 18) and and/or any suitable wired and/or wireless communication device that receives signals from the device. In the exemplary embodiment, memory 104 may comprise any suitable storage device including, but not limited to, flash memory, electrically erasable programmable memory, read-only memory (ROM), removable media, and/or other volatile and non-volatile storage devices. In one embodiment, executable instructions (ie, software instructions) are stored in memory 104 for use by controller 102 in controlling pitch drive system 68 as described below.

In the exemplary embodiment, controller 102 is a real-time controller comprising any suitable processor-based or microprocessor-based system, such as a computer system, including a microcontroller , a reduced instruction set circuit (RISC), an application specific integrated circuit (ASIC), a logic circuit, and/or any other circuit or processor capable of performing the functions described herein. In one embodiment, the controller 102 may be a microprocessor including read only memory (ROM) and/or random access memory (RAM), such as, for example, a 32bit microcomputer with 2Mbit ROM and 64Kbit RAM. As used herein, the term "real-time" refers to an output occurring a very short period of time after a change in an input affects the output, which may be based on the importance of the output and/or the ability of the system to process the input to produce the output The selected design parameters.

In the exemplary embodiment, sensors of sensor system 94 , such as speed sensor 70 , are coupled to rotor shaft 44 to facilitate measuring the rotational speed of rotor 18 . Sensor system 94 may include sensors mounted on wind turbine 10 at any suitable location that enables the sensors to measure a variable of wind turbine 10, such as the rotational speed of rotor 18, or a rotational speed proportional thereto, such as a high speed shaft 48 rpm.

According to some embodiments, the controller 102 is programmed to determine an actual value of the first variable indicative of an overspeed condition of the wind turbine 10 . In the exemplary embodiment, the sensors of sensor system 94 are communicatively coupled to controller 102 via sensor interface 108 of communication module 106 via any suitable wired and/or wireless communication medium to facilitate enabling the sensors to transmit signals to and/or receive signals from the controller 102 . In the exemplary embodiment, speed sensor 70 continuously measures the actual value of the rotational speed of rotor 18 and speed sensor 70 continuously and in real time transmits a signal indicative of the measured actual value of rotor speed to controller 102 . In one embodiment, the controller 102 is programmed to continuously receive and monitor the signal transmitted by the speed sensor 70 . In an alternative embodiment, the controller 102 may not continuously receive and/or monitor signals transmitted by the speed sensor 70, but instead be programmed to repeatedly request signals from the speed sensor 70 at predetermined time intervals. In some embodiments, controller 102 and/or speed sensor 70 may transmit signals to and/or receive signals from each other at any suitable time interval. Alternative or additional sensors of sensor system 94 communicate with controller 102 in a similar manner to transmit measured actual values of variables of wind turbine 10 to controller 102 .

According to some embodiments, the controller 102 is programmed to determine the actual value of the second variable of the wind turbine 10 related to the rate of change of the first variable with respect to time. Typically, the second variable is related to the rate of change of the first variable with respect to time in such a way that changes in the second variable are accompanied by changes in the time rate, and changes in the time rate are usually Parallel to changes in the second variable. In the exemplary embodiment, controller 102 is programmed to determine the rate of change of the rotational speed of rotor 18 with respect to time based on the measured actual value of the rotor speed. In this manner, the example controller 102 determines a second variable (in this case, the rotation of the rotor 18 ) of the wind turbine 10 based on the rate of change of the first variable (ie, in this case, the rotational speed of the rotor 18 ) with respect to time. Acceleration) the actual value. In other alternative embodiments, the controller 102 may determine the actual value of the second variable for the wind turbine from data measured by sensors forming part of the sensor system 94 . For example, the controller 102 may determine the actual value of the rotational acceleration from data measured by an acceleration sensor forming part of the sensor system 18 . In other alternative embodiments, the controller 102 may determine the second rate of change of the wind turbine based on the rate of change with respect to time of other variables of the wind turbine, such as, but not limited to, the rotational speed of the high speed shaft 48 or the power output of the wind turbine 10 . Actual value of a variable (eg rotor acceleration).

During operation of exemplary wind turbine 10, controller 102 is programmed to receive a signal corresponding to an actual value of at least one variable of the wind turbine, such as measured data provided by speed sensor 70, and controller 102 is programmed to cause the wind turbine variable The value of is associated with each signal to determine at least one actual value of the variable. For example, the controller 102 may be programmed to correlate the value of the rotational speed of the rotor 18 with the signal from the speed sensor 70 to determine the actual value of the rotational speed of the rotor 18 . According to some embodiments, the controller 102 is programmed to correlate the value of the second variable of the wind turbine with the signal from the sensor of the sensor system 94 . For example, the controller 102 can be programmed to correlate the value of the rotational acceleration of the rotor 18 with the signal of the acceleration sensor to determine the actual value of the acceleration of the rotor 18 .

In the exemplary embodiment, controller 102 is programmed to store data in memory 104 indicative of an overspeed condition (ie, an overspeed condition of rotor 18 ). For example, controller 102 may store the maximum allowable speed of the wind turbine. At this speed, the rotor 18 is considered to be in an overspeed condition. In another embodiment, the controller 102 stores a look-up table that correlates values of the first variable and the second variable of the wind turbine 10 with the occurrence of overspeed. For example, such a lookup table may correlate rotor speed and rotor acceleration values that cause an overspeed condition of wind turbine 10 to occur within a predetermined period of time.

According to some embodiments, the controller 102 is programmed to estimate the occurrence of an overspeed condition of the wind turbine 10 from at least the determined actual values of the first variable and the second variable. Specifically, according to certain embodiments, after determining the actual values of the first variable and the second variable of the wind turbine 10 , the controller 102 is programmed to evaluate these values for estimation with respect to identifying an overspeed condition of the wind turbine 10 . In the exemplary embodiment, controller 102 is programmed to evaluate at least one of the determined values of rotor speed and rotor acceleration to identify the occurrence of an overspeed condition of wind turbine 10 . As used herein, the term "identifying an overspeed condition" is intended to mean a process for inferring the occurrence of a current overspeed condition or estimating that an overspeed condition will occur within a predetermined period of time, or for identifying a variable of a wind turbine A value that causes an overspeed condition to occur for a predetermined period of time.

According to some embodiments, the controller 102 is programmed to identify a future rotor speed based on determined actual values of the first variable and the second variable of the wind turbine 10, and typically compares the identified future rotor speed to a predetermined Rotor speed value to estimate the presence of an overspeed condition.

In one embodiment, to evaluate the determined actual values of the first variable and the second variable to identify an overspeed condition, the controller 102 is programmed to continuously input the actual values of the first variable and the second variable to facilitate identification of the overspeed condition in the mathematical model. According to at least some embodiments, controller 102 is programmed to identify a future rotor speed based on the determined actual values of the first variable and the second variable. For example, in one embodiment, the controller 102 is programmed to input the actual value v _i of the rotor speed and the actual value a i of the rotor acceleration a _i into the formula v _i + a _i T to identify the time period T The future rotor speed occurring in . In one embodiment, the predetermined time period T ranges from about 0.1 second to 5 seconds, or more specifically, 0.5 second to 4 seconds, or even more specifically, 1 second to 3 seconds. In one embodiment, the predetermined time period T ranges from about 1 second to 3 seconds. Alternatively, predetermined time period T may be any suitable time period that enables controller 102 to adequately identify future rotor speeds. According to at least some of these embodiments, controller 102 is further programmed to compare the identified future rotor speed to a predetermined rotor speed value to identify an overspeed condition of wind turbine 10 .

Typically, the predetermined rotor speed value corresponds to a maximum allowable speed of the wind turbine, which is predetermined by evaluating specific characteristics of the wind turbine 10 . Typically, the maximum allowable speed is predetermined by taking into account the physical properties of the blade tip. In particular, the maximum allowable speed corresponds to the rotor speed at which the speed on the outer portion of the rotor blade 22 (i.e. the edge speed) does not exceed a speed between 70 m/s and 110 m/s or more specifically A speed between 80m/s and 100m/s (eg 90m/s). In some embodiments, it is predetermined by considering the maximum allowable loads on certain components of the wind turbine (such as rotor bearings) caused by the rotation of the rotor 18 or acting on the tower 12 or nacelle 16 The maximum allowable speed of the wind turbine 10 . In some embodiments, the maximum allowable speed is predetermined by taking into account the maximum allowable noise generation of wind turbine 10 . In some embodiments, the maximum allowable speed may vary depending on the particular conditions wind turbine 10 is experiencing. For example, according to some embodiments implemented in offshore wind turbines, the magnitude (ie force) or power density and/or frequency of ocean waves impinging on wind turbine 10 is considered to determine the maximum allowable speed at a particular time.

Alternatively, any suitable mathematical model that enables wind controller 102 to identify an overspeed condition as described herein may be used. Such a suitable mathematical model may be a model that takes as input the above-mentioned acceleration related to gravity and its rate of change with respect to time. Alternatively, such a suitable mathematical model may be a model that takes as additional inputs the wind speed and its rate of change with respect to time. Typically, the mathematical model takes as input a combination of variables corresponding to the level of a certain magnitude of the wind turbine 10 and its rate of change with respect to time. According to some embodiments, a mathematical model taking as input more than two variables of wind turbine 10 is implemented in controller 102 to identify future values of rotor speed. For example, such a mathematical model may take as input the second, third or even higher order derivatives of the rotor speed in order to identify future values of the rotor values in an accurate manner. Typically, such mathematical models are based on finite Taylor series that provide an approximation of the future value of the rotor speed over a period of time. In another example, a mathematical model that takes power output and rotor acceleration as inputs is implemented in controller 102 to identify future values of rotor speed.

According to some embodiments, the controller 102 is programmed to identify a time period for reaching a predetermined rotor speed value based on the determined actual values of the first variable and the second variable of the wind turbine, and typically compare the identified time period and a predetermined time period. In one embodiment, the controller 102 is programmed to infer the time period for reaching the predetermined rotor speed value based on the determined actual values of the first variable and the second variable according to a mathematical model, and compare the identified times to period and a predetermined time period. For example, the controller 102 may determine the time required to reach the maximum allowable speed of the wind turbine 10 by inputting the actual value v _i of the rotor speed and the actual value a _i of the rotor acceleration a i into the formula (Vv _i ) a _i , to estimate the occurrence of overspeed V. If the determined time period is below the predetermined time period, the controller 102 recognizes the occurrence of an overspeed condition and accordingly signals the pitch drive system 68 for rotating the rotor blades 22 . Typically, the predetermined time period ranges from about 0.1 seconds to 5 seconds, or, more specifically, 0.5 seconds to 4 seconds, or, even more specifically, 1 second to 3 seconds.

According to some embodiments, the controller 102 is programmed to estimate the occurrence of an overspeed condition of the wind turbine by initiating the logic algorithm as soon as the value of the first variable indicative of the overspeed condition of the wind turbine 10 exceeds a predetermined value. For example, according to some embodiments, the logic is activated when the rotor speed exceeds a value between 85%-95% (eg, 90%) of the maximum allowed rotor speed. Alternatively, the logic is activated when the power output of the wind turbine 10 exceeds a value between 85%-95% (eg 90%) of the maximum allowed power output. Alternatively, the logic is activated when the wind speed in the environment of the wind turbine 10 exceeds a value between 8m/s-12m/s, eg 10m/s. Once the logic is activated and as long as the first variable exceeds the predetermined value, the controller 102 estimates the occurrence of an overspeed condition by calculating a future value of the first variable that will occur within the predetermined time period. Typically, the predetermined time period ranges from about 0.1 seconds to 5 seconds, or, more specifically, 0.5 seconds to 4 seconds, or, even more specifically, 1 second to 3 seconds.

According to some embodiments, the controller 102 is programmed to verify the determined actual values of the first variable and the second variable of the wind turbine 10 by comparing these values with a list of predetermined values (the determined values of the first variable and the second variable determined actual value) to estimate the occurrence of an overspeed condition of the wind turbine 10. In one embodiment, the controller 102 may store a look-up table containing a list of predetermined values for the first variable and the second variable of the wind turbine 10 to identify which combination of these values will result in an overspeed condition within a certain period of time . Specifically, controller 102 may store a look-up table containing predetermined values for rotor speed and rotor acceleration. By verifying the actual values of rotor speed and rotor acceleration in the lookup tables, controller 102 can estimate the occurrence of an overspeed condition of wind turbine 10 . Specifically, the lookup table may instruct controller 102 to signal pitch drive system 68 to pitch rotor blades 22 to aerodynamically brake rotor 18 through certain combinations of actual values.

Typically by considering wind turbine dynamics and maximum allowable parameters of wind turbine 10 such as but not limited to loads acting on certain components such as tower 12, nacelle 16 or bearings in wind turbine 10 and noise generation Appropriate modeling to predetermine the lookup tables mentioned above. Alternatively, the table is predetermined by any suitable method that enables wind controller 102 to estimate the occurrence of an overspeed condition as described herein. In an alternative embodiment, the evaluation is performed based on a table relating values of other variables such as power output and rotor acceleration, or rotor speed and rate of change of power output with respect to time. According to certain embodiments, the look-up table takes as input three or more variables of the wind turbine or other parameters associated therewith such as, but not limited to, wind speed. According to some embodiments, a look-up table and a mathematical model having as input at least one variable of the wind turbine 10 are implemented in the controller 102 to estimate the occurrence of an overspeed condition.

According to some embodiments, the controller 102 further estimates based on the determined actual value of the wind speed to identify an overspeed condition of the wind turbine 10 . For example, controller 102 may input actual values of rotor speed, rotor acceleration, and wind speed into an appropriate mathematical model to identify wind turbine overspeed. In this manner, the controller 102 is facilitated in estimating the occurrence of an overspeed condition in an accurate and reliable manner. In another example regarding offshore wind turbines, the magnitude (ie force) or power density and/or frequency of ocean waves impinging on wind turbine 10 is considered to estimate the occurrence of overspeeding of wind turbine 10 .

According to some embodiments, controller 102 identifies an overspeed condition based on at least one of the curvature of rotor blades 22 , the power output of wind turbine 10 , and/or the rotational speed of wind turbine 10 that is proportional to the rotational speed of the rotor. According to some embodiments, controller 102 further bases the evaluation on the rate of change of at least one of these variables.

In the exemplary embodiment, controller 102 is further programmed to control at least one pitch drive system 68 to aerodynamically brake rotor 18 when controller 102 affirmatively estimates the occurrence of an overspeed condition. In one embodiment, the controller 102 is programmed to identify a future rotor speed based on the determined actual values of the first variable and the second variable, compare the identified future rotor speed to a predetermined rotor speed value to identify the wind turbine 10 and controlling pitch drive system 68 when the identified future rotor speed is at or above a predetermined rotor speed value. In one embodiment, controller 102 is configured to control pitch drive system 68 to move rotor blades 22 to a feathered position such that rotation of rotor 18 is slowed in response to the identified occurrence of a future overspeed condition.

According to some embodiments, pitch drive system 68 pitches rotor blades 22 at a pitch rate determined based at least on a determined actual value of at least one of the first variable and/or the second variable. In the exemplary embodiment, controller 102 determines a pitch rate for controlling at least one pitch drive system 68 . Controller 102 may determine the pitch rate based on the determined actual values of rotor speed and rotor acceleration. Typically, by considering the actual values of both variables, the blades 22 are pitched at a lower pitch rate than would be the case where only the actual rotor speed is considered. Accordingly, these embodiments facilitate smooth pitching of rotor blades 22 in response to conditions of wind turbine 10 that may result in an overspeed condition. The higher the pitch rate, the higher the number of excited resonant frequencies of wind turbine 10 . Accordingly, these embodiments facilitate the excitation of only a small number of resonant frequencies during pitching, and thus pitch-induced tower vibrations typically remain low.

According to some embodiments, the controller 102 determines the pitch rate by taking into account a predetermined maximum rotor braking rate. Typically, pitch drive system 68 rotates rotor blades 22 in such a manner that braking of rotor 18 does not exceed a predetermined maximum rotor braking rate. In one embodiment, the pitch rate is determined by considering a predetermined maximum load, such as, but not limited to, a maximum predetermined load of the rotor bearings, tower 12 or nacelle 16 . Typically, in this embodiment, pitch drive system 68 rotates rotor blades 22 in such a manner that the load on wind turbine 10 does not exceed a predetermined maximum load. For example, controller 102 may determine actual values of loads acting on certain components of wind turbine 10, such as, but not limited to, loads on rotor bearings, tower 12, or nacelle 16, and determine such that the loads do not exceed a predetermined The pitch rate that aerodynamically brakes the rotor 18 is achieved in the manner of the maximum load. In certain embodiments, pitch drive system 68 rotates rotor blades 22 in such a manner that a first variable (eg, rotor speed) of wind turbine 10 does not exceed a threshold (eg, the above-mentioned maximum allowable rotor speed).

FIG. 5 is a flowchart illustrating an example method 500 for operating wind turbine 10 in FIG. 1 . In the exemplary embodiment, method 500 includes determining 502 an actual value of a first variable indicative of an overspeed condition of wind turbine 10 . Typically, the first variable is monotonically related to the rotational speed of the rotor 18 . For example, the first variable corresponds to the rotor speed, the curvature of the rotor blades 22, the power output of the wind turbine 10, or the rotational speed of the wind turbine 10 (which is directly proportional to the rotational speed of the rotor, such as the speed of the high speed shaft 48 or the speed of the generator 42). speed). Alternatively, the first variable may correspond to the above mentioned acceleration related to gravity. Exemplary method 500 further includes determining an actual value of wind turbine 10 for a second variable related to the rate of change of the first variable with respect to time. Typically, the second variable is monotonically related to the rotational acceleration of the rotor 18 .

Exemplary method 500 further includes estimating 506 the occurrence of an overspeed condition of wind turbine 10 based on at least the determined actual values of the first variable and the second variable. According to some embodiments, estimating 506 includes identifying a future rotor speed based on determined actual values of the first variable and the second variable, and optionally comparing the identified future rotor speed with a predetermined rotor speed value to identify Overspeed condition of wind turbine 10 . According to some embodiments, estimating 506 includes identifying a time period for reaching a predetermined rotor speed value based on the determined actual values of the first variable and the second variable, and comparing the identified time period to the predetermined time period . According to some embodiments, estimating 506 includes validating the determined actual values of the first variable and the second variable by comparing these values (determined actual values of the first variable and the second variable) with a list of predetermined values. Therefore, it is advantageous to estimate the occurrence of the overspeed state.

Exemplary method 500 further includes pitching 510 rotor blades 22 based on estimated results 508 to aerodynamically brake rotor 18 . Typically, rotor blades 22 are rotated when it is estimated 508 that an overspeed condition will occur within a predetermined time. According to certain embodiments, pitch drive system 68 rotates rotor blades 22 when an overspeed condition is identified. Specifically, pitch drive system 68 typically pitches rotor blades 22 as soon as the occurrence of an overspeed condition is identified in the estimate or with a delay corresponding to a predetermined time.

FIG. 6 is a flowchart illustrating another exemplary method 600 of operating the wind turbine in FIG. 1 . In the exemplary embodiment, method 600 includes determining 602 an actual value of a reference speed that is proportional to a rotational speed of the rotor. Typically, the reference speed corresponds to the rotor speed, the rotational speed of the high speed shaft 48 , or the speed of a rotatable portion of the wind turbine 10 coupled to the rotor 18 . Typically, the reference speed indicates an overspeed condition of the wind turbine 10 when it exceeds a threshold. Typically, the threshold speed corresponds to the maximum allowed speed of the reference speed. Exemplary method 600 further includes determining 604 an actual value of the rate of change of the reference speed with respect to time. Typically, this rate of change corresponds to the acceleration of the rotor 18 . Exemplary method 600 further includes evaluating 606 the determined actual value of the reference speed and the rate of change of the reference speed with respect to time to identify an overspeed condition of the wind turbine. Exemplary method 600 further includes identifying 608 an overspeed condition based on the results of evaluating 606 . When an overspeed condition is identified, pitch drive system 68 rotates rotor blades 22 in step 610 .

7 is a schematic graphical representation of the response to an identified overspeed condition of the wind turbine in FIG. 1 as compared to a known overspeed of the wind turbine due to an increase in wind speed. Specifically, the graph shows the response of the wind turbine during a time period of approximately 13 seconds (ie, corresponding to the horizontal axis of the graph). Graph A shows a time series graph of wind speed 700 that typically results in an increase in rotor speed. In graph A the wind speed is shown in meters per second (m/s). In graph B the increase in rotor speed caused by wind speed 700 is shown for at least one known wind turbine (line 702 ), while in graph C a wind turbine according to the above exemplary embodiment is shown ( The increase in rotor speed caused by wind speed 700, line 706). The rotor speed is shown in revolutions per minute (l/m) in both graphs. In known wind turbines, the rotor speed 702 at time t1 exceeds a predetermined rotor speed value 703 corresponding to rotor overspeed. In known wind turbines, as soon as the rotor speed 702 exceeds a predetermined value 703 (ie at time t1 ), the blade angle is changed (line 704 ) to reduce the rotor speed.

As shown in graph C of FIG. 7 , in the exemplary embodiment, when the controller of the wind turbine identifies an overspeed condition based on the above-mentioned estimates, the blade angle is changed (line 708 ) to lower the rotor speed. speed. Specifically, the exemplary wind turbine estimates at time t1 ′ (a time constant prior to t1 ) that a future overspeed condition of the wind turbine will occur within a certain time based on actual values of rotor speed and rotor acceleration. In the exemplary embodiment, pitch drive system 68 rotates rotor blade 22 at time t1 ′. That is, in the exemplary embodiment, the wind turbine begins pitching before rotor speed 706 will reach predetermined value 703 corresponding to rotor overspeed. Accordingly, controller 102 in the exemplary embodiment recognizes the occurrence of a future overspeed condition and reacts before the wind turbine enters the estimated overspeed condition. Accordingly, the exemplary wind turbine is able to perform a smoother pitch than known wind turbines to reduce rotor speed in response to an increase in wind speed that could result in an overspeed condition of the wind turbine. Thus, pitching of the exemplary wind turbine results in smoother braking of the rotor and thus reduces transient loads on wind turbine components compared to known wind turbines.

In general, pitching the blades in a wind turbine to reduce rotor speed means pulling the wind turbine against the wind (ie it causes the wind tower to deflect towards the wind). This pull typically increases with pitch rate. Graph D shows the tower deflection 710 in response to a change in blade angle 704 of the known wind turbine in graph B, and the tower deflection 710 in response to a change in blade angle 708 of the exemplary embodiment in graph C. Deflect 712. The known wind turbine is pulled against the wind during time t1 and time t2, while the wind turbine in the exemplary embodiment is pulled against the wind during time t1' and time t2'. Because the wind turbine in the exemplary embodiment is pitched at a lower pitch rate, the corresponding deflection of the wind turbine tower is lower than known wind turbines. At time t2, the rotor speed 702 of the known wind turbine is reduced back below the predetermined value 703 and the blade angle is changed 704 in the opposite direction to keep the rotor speed as high as possible. Thus, between time t2 and time t3 , the wind turbine tower in the known wind turbine is pushed relative to the wind, as shown by tower deflection 710 .

This pulling and pushing in known wind turbines excites the resonant frequency of the tower, as shown in graph D by tower deflection 710 . In graph D the tower vibration is shown in units of milligravity (1 g = 9.81 m/s ² ). Generally, such resonances of known wind turbines require shutting down the wind turbine. In contrast, due to the lower pitch rate in the exemplary wind turbine, the corresponding tower deflection 712 is lower than in known wind turbines. In this example, tower deflection 712 does not cause resonance of the tower. Thus, in this example, pitching the exemplary wind turbine need not shut it down when an overspeed condition is identified. Furthermore, the loads acting on the exemplary wind turbine during pitching are significantly reduced compared to known wind turbines.

Exemplary embodiments of systems and methods for operating a wind turbine are described above in detail. The systems and methods are not limited to the particular embodiments described herein, but rather, components of the systems and/or steps of the methods may be used individually and separately from other components and/or steps described herein. For example, the method may evaluate the value of a variable determined by a sensor and the value of another variable determined using a suitable mathematical model that takes as input the first variable and other dynamic variables (such as wind speed), and is not limited to only those described herein. wind turbine system practice. Rather, the exemplary embodiment may be implemented and used in conjunction with many other rotor blade applications.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. While various specific embodiments have been disclosed in the foregoing description, those skilled in the art will recognize that the spirit and scope of the claims allow for equally effective modifications. In particular, mutually non-exclusive features of the embodiments described above may be combined with each other. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal language of the claims .

Claims (21)

1. one kind for running the method for wind turbine, described wind turbine comprises rotor, described rotor comprises at least one rotor blade and is connected to the change oar drive system at least one rotor blade described, described change oar drive system is configured to make at least one rotor blade described become oar, and described method comprises:

Determine the actual value of the first variable of the overspeed condition indicating described wind turbine;

That determine described wind turbine to the bivariate actual value relevant relative to the variance ratio of time that be described first variable; And,

The appearance of the overspeed condition of described wind turbine is at least estimated from described first variable and bivariate determined actual value,

Wherein, described change oar drive system makes at least one rotor blade described become oar, so that in aerodynamic mode to described rotor brake based on the result of described estimation.

2. method according to claim 1, it is characterized in that, when the result of described estimation be overspeed condition can occur within the predetermined time time, described change oar drive system makes at least one rotor blade described become oar, so that in aerodynamic mode to described rotor brake.

3. method according to claim 1, it is characterized in that, described estimation comprises and identifies following spinner velocity based on described first variable and bivariate described determined actual value, and wherein, described following spinner velocity will be between about 0.5 second and about 4 seconds future.

4. method according to claim 3, is characterized in that, described estimation comprises further compares identified described following spinner velocity and predetermined spinner velocity value.

5. method according to claim 1, it is characterized in that, described estimation comprises and identifies time period for arriving predetermined spinner velocity value based on described first variable and bivariate described determined actual value, and compares identified described time period and predetermined time period.

6. method according to claim 1, it is characterized in that, described estimation comprises verifies described first variable and bivariate described determined actual value by the following: more described value and a row predetermined value, to estimate the appearance of the overspeed condition of described wind turbine.

7. method according to claim 1, it is characterized in that, described first variable corresponds to one in the rotating speed of the tortuosity of at least one rotor blade described, the power stage of described wind turbine or described wind turbine, and described rotating speed is directly proportional to the rotating speed of described rotor.

8. method according to claim 1, it is characterized in that, comprise the change oar speed determining at least one rotor blade described is rotated further, wherein, at least determine described change oar speed based on described first variable or described bivariate described determined actual value.

9. method according to claim 8, it is characterized in that, determine that described change oar speed comprises and consider predetermined maximum rotor braking speed, and described change oar drive system makes at least one rotor blade described become oar in the mode making the braking of described rotor and be no more than described predetermined maximum rotor braking speed.

10. method according to claim 1, is characterized in that, described change oar drive system makes at least one rotor blade described become oar in the mode making described first variable and be no more than threshold value.

11. methods according to claim 1, is characterized in that, determine that the described bivariate described actual value of described wind turbine comprises the variance ratio relative to the time of at least two actual values calculating described first variable.

12. methods according to claim 1, it is characterized in that, also comprise the actual value of the wind speed determined in the region of described wind turbine, wherein, described estimation further based on the actual value of determined wind speed, to identify the overspeed condition of described wind turbine.

13. 1 kinds of control units for wind turbine, described wind turbine comprises rotor, and described rotor comprises at least one rotor blade, and described control unit comprises:

Be connected to the change oar drive system at least one rotor blade described, described change oar drive system is configured to make at least one rotor blade described become oar; With

Communicatively be connected to the control system in described change oar drive system, described control system is configured to:

Determine the actual value of the first variable of the overspeed condition indicating described wind turbine;

That determine described wind turbine to the bivariate actual value relevant relative to the variance ratio of time that be described first variable; And,

The appearance of the overspeed condition of described wind turbine is at least estimated from described first variable and bivariate described determined actual value; And

Wherein, described control system is configured to control described change oar drive system by this way based on the result of described estimation: make described control become oar drive system and make at least one rotor blade described become oar, so that in aerodynamic mode to described rotor brake.

14. control units according to claim 13, it is characterized in that, comprise the sensing system be communicatively connected in described control system further, described sensing system is configured to measure at least one in the described actual value of described first variable or described bivariate described actual value.

15. control units according to claim 14, it is characterized in that, described sensing system is suitable for being connected in the rotatable portion of described wind turbine, described rotatable portion is connected on described rotor, sets up at least one in the described actual value of described first variable or described bivariate described actual value with the rotating speed by measuring described rotatable portion.

16. control units according to claim 14, it is characterized in that, described sensing system is suitable for being connected on the master section of described wind turbine, sets up at least one in the actual value of described first variable or described bivariate actual value with the power stage by measuring described master section.

17. control units according to claim 14, it is characterized in that, described sensing system is configured to the actual value of the wind speed measured in the region of described wind turbine further, and described control system is configured to perform described estimation based on the actual value of determined wind speed.

18. control units according to claim 14, it is characterized in that, described wind turbine comprises pylon further, and wherein, described sensing system is configured to the actual value measuring the described tortuosity of at least one rotor blade or the vibration of described pylon further.

19. 1 kinds for running the method for wind turbine, described wind turbine comprises rotor, described rotor comprises at least one rotor blade and is connected to the change oar drive system on this at least one rotor blade, described change oar drive system is configured to make at least one rotor blade described become oar, and described method comprises:

Determine the actual value of the reference speed be directly proportional to the rotating speed of rotor;

Determine the actual value of the variance ratio relative to the time of described reference speed; And,

Evaluate the determined actual value of described reference speed and the variance ratio relative to the time of described reference speed, to identify the overspeed condition of described wind turbine;

Wherein, when recognizing the overspeed condition of described wind turbine in described evaluation, described change oar drive system makes at least one rotor blade described rotate.

20. methods according to claim 1, is characterized in that, described estimating part ground is based on the look-up table making described first variable and bivariate value be associated with the appearance of described overspeed condition.

21. methods according to claim 13, is characterized in that, described estimating part ground is based on the look-up table making described first variable and bivariate value be associated with the appearance of described overspeed condition.